This invention relates to wellbore fluids, including drilling fluids, completion fluids, workover fluids, packer fluids, that is, all of those fluids which are employed over the course of the life of a well.
Generally wellbore fluids will be either clay-based or brines which are clay-free. These two classes are exclusive, that is, clay-based drilling fluids are not brines. A wellbore fluid can perform any one or more of a number of functions. For example, the drilling fluid will generally provide a cooling medium for the rotary bit and a means to carry off the drilled particles. Since great volumes of drilling fluid are required for these two purposes, the fluids have been based on water. Water alone, however, does not have the capacity to carry the drilled particles from the borehole to the surface.
In the drilling fluid class, clay-based fluids have for years preempted the field, because of the traditional and widely held theory in the field that the viscosity suitable for creating a particle carrying capacity in the drilling fluid could be achieved only with a drilling fluid having thixotropic properties, that is, the viscosity must be supplied by a material that will have sufficient gel strength to prevent the drilled particles from separating from the drilling fluid when agitation of the drilling fluid has ceased, for example, in a holding tank at the surface.
In order to obtain the requisite thixotropy or gel strength, hydratable clay or colloidal clay bodies such as bentonite or fuller's earth have been employed. As a result the drilling fluids are usually referred to as "muds." The use of clay-based drilling muds has provided the means of meeting the two basic requirements of drilling fluids, i.e., cooling and particle removal. However, the clay-based drilling muds have created problems for which solutions are needed. For example, since the clays must be hydrated in order to function, it is not possible to employ hydration inhibitors, such as calcium chloride, or if employed, their presence must be at a level which will not interfere with the clay hydration. In certain types of shales generally found in the Gulf Coast area of Texas and Louisiana, there is a tendency for the shale to disintegrate by swelling or cracking upon contact with the water if hydration is not limited. Thus the uninhibited clay-based drilling fluids will be prone to shale disintegration.
The drilled particles and any heaving shale material will be hydrated and taken up by the conventional clay-based drilling fluids. The continued addition of extraneous hydrated solid particles to the drilling fluid will increase the viscosity and necessitated costly and constant thinning and reformulation of the drilling mud to maintain its original properties.
Another serious disadvantage of the clay-based fluids is their susceptibility to the detrimental effect of brines which are often found in drilled formations, particularly Gulf Coast formations. Such brines can have a hydration inhibiting effect, detrimental to the hydration requirement for the clays.
Other disadvantages of clay-based drilling fluids are their (1) tendency to prevent the escape of gas bubbles, when the viscosity of the mud rises too high by the incidental addition of hydratable material, which can result in blow-outs; (2) the need for constant human control and supervision of the clay-based fluids because of the exceptable, yet unpredictable, variations in properties; and (3) the formation of a thick cake on the internal surfaces of the wellbore.
The brines have the advantage of containing hydration inhibiting materials such as potassium chloride, calcium chloride or the like. Quite apparently any solid particulate material would be easily separated from the brine solution since it is not hydrated. Thus, the properties of the brine are not changed by solid particulate matter from the wellbore. Similarly, since there is no opportunity for gas bubbles to become entrapped, blowouts are less likely in a clay-free brine-type wellbore fluid.
Non-argillaceous (clay-free) wellbore fluids based on non thixotropic viscosifiers have been developed, which overcome the problems noted above with the clay-based fluids, such as a brine containing a viscosifying amount of magnesia stabilized hydroxyethyl cellulose described in detail in the copending application of Jack M. Jackson, Ser. No. 343,288 filed Mar. 21, 1973.
Thus, although these two principal water-based, competing and incompatible systems are commercially available and used, there is yet a hiatus, in a manner of speaking, between the capacities and desirable properties of these two systems. Thus, even though the clay-free systems described avoid the problems of the clay-based systems, they are not suitable for systems where weighting materials such as calcium carbonate are necessary or desired, especially if the weighting material is used in substantial quantities.
A material which has come into expanding use in wellbore fluids is heteropolysaccharide produced by the action of bacteria of the genus Xanthomonas on carbohydrates, such as described in U.S. Pat. Nos. 3,198,268; 3,208,526; 3,251,417; 3,243,000; 3,305,016; and 3,319,715. This material has been employed for a number of functions in wellbore fluids, e.g. fluid loss additive, foaming agent, and viscosifier. Generally these heteropolysaccharides are employed with clays; however, they need not be, and in U.S. Pat. No. 3,319,715 they are disclosed to be useful in brine completion fluids.
It is a feature of the present invention that the heteropolysaccharides produced by the action of the genus Xanthomonas bacteria is employed as a thixotropic viscosifier in a clay-free wellbore fluid in conjunction with a specified class of water loss control additives having improved down hole properties, and which can contain weighting materials. These and other features and advantages will be apparent from the following discussion and description of the invention and the preferred embodiments.